32
OPERATING EXPERIENCE OF LARGE REHEAT HRSGs in MERCHANT SERVICE Peter S. Jackson, PE TETRA ENGINEERING GROUP David S. Moelling, PE TETRA ENGINEERING GROUP Frederick C. Anderson, PE TETRA ENGINEERING GROUP James W. Malloy TETRA ENGINEERING EUROPE Abstract Tetra Engineering has inspected over 50 large Reheat HRSG's in the past 4 years representing all major HRSG OEMs. The plants represent all NERC Regions and operating conditions. Almost all of these are relatively new units entering merchant service. This paper will describe the issues and problems found in the areas of commissioning, supplemental firing, controls for temperature, startup and drains, fabrication and erection quality, corrosion control, critical piping issues and design issues. Case Studies and examples of the most prevalent problems will be discussed as well as industry wide conclusions. In general, HRSG reliability and availability has been quite good, but the demands on merchant units for commercial availability require the continued maintenance of high availability and low cost of maintenance. Summary of Operating Experiences Most large new combined cycle plants in the US were designed under the assumption that they would be baseloaded, or at least infrequently cycled. This basic assumption has proven to be far from actual operating modes for most new plants as indicated in Figure 1. Two-Shift cycling is differentiated from Seasonal Duty where plants are run essentially baseload, but only for a few months of the year. New plants include those that are commissioned but not running or which were inspected close to the time of commissioning.

OPERATING EXPERIENCE OF LARGE REHEAT HRSGs in …Larger thermal stresses result with significant implications for fatigue life of ... distortion from thermal expansion and interference

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  • OPERATING EXPERIENCE OF LARGE REHEAT HRSGs in MERCHANT SERVICE

    Peter S. Jackson, PE TETRA ENGINEERING GROUP

    David S. Moelling, PE TETRA ENGINEERING GROUP

    Frederick C. Anderson, PE TETRA ENGINEERING GROUP

    James W. Malloy TETRA ENGINEERING EUROPE

    Abstract

    Tetra Engineering has inspected over 50 large Reheat HRSG's in the past 4 years

    representing all major HRSG OEMs. The plants represent all NERC Regions and

    operating conditions. Almost all of these are relatively new units entering merchant

    service.

    This paper will describe the issues and problems found in the areas of commissioning,

    supplemental firing, controls for temperature, startup and drains, fabrication and

    erection quality, corrosion control, critical piping issues and design issues. Case Studies

    and examples of the most prevalent problems will be discussed as well as industry wide

    conclusions. In general, HRSG reliability and availability has been quite good, but the

    demands on merchant units for commercial availability require the continued

    maintenance of high availability and low cost of maintenance.

    Summary of Operating Experiences

    Most large new combined cycle plants in the US were designed under the assumption

    that they would be baseloaded, or at least infrequently cycled. This basic assumption

    has proven to be far from actual operating modes for most new plants as indicated in

    Figure 1. Two-Shift cycling is differentiated from Seasonal Duty where plants are run

    essentially baseload, but only for a few months of the year. New plants include those

    that are commissioned but not running or which were inspected close to the time of

    commissioning.

  • Since combustion turbine ramp rates and startup procedures directly affect HRSG

    component temperature ramp rates, the push to rapid CT startups results in greater

    ramp rates in HRSG hot section components than was assumed in plant design

    analyses. Larger thermal stresses result with significant implications for fatigue life of

    affected components such as drums, thick section headers and tube-to-header welds.

    0% 5% 10% 15% 20% 25% 30% 35%

    Two-Shift

    Seasonal Duty

    New

    Baseload

    Peaking

    AGC

    Figure 1. Operating Modes of Inspected HRSGs

    In additions, rapid thermal response results in more condensate accumulation during

    startups and a greater requirement for attermperation spray to control piping metal

    temperatures. These extreme conditions that are caused by cycling operations

    sometimes result in waterhammer in affected piping systems, thermal quenching of hot

    component surfaces and in some instance leakage or failure of the pressure boundary

    at tube-to-header welds, riser piping to drums, crossover (connecting) piping and drain

  • connections. Cold weather operations also provide a different challenge with the need

    to maintain temperature to prevent header failure from freezing conditions.

    While new plants have operated in general significantly less than originally assumed,

    most have pursued an aggressive approach to assure that HRSG component integrity is

    verified by periodic inspections; usually during scheduled outages when the CT

    maintenance has been scheduled. A thorough inspection of a large HRSG (for

    example, behind a Frame 7FA, or 501F/G CT) with reheater components typically

    requires about 2 days for a crew of 2 people. These inspections are more detailed than

    statutory “boiler” inspections and typically include the following activities:

    1. visual inspection of HRSG gas path components: tubes, headers and their

    supports, crossover piping, risers, drains, gas baffles, acoustic baffles and

    related structural components.

    2. ultrasonic testing (UT) of wall thickness for selected (high risk) tube, header and

    riser components, thereby establishing the condition of HRSG components early

    in life. Drum baffle plates and in some instances cyclone separator “can”

    thickness are also measured at some plants.

    3. visual inspection of accessible HRSG water-side components (for large

    combined cycle plants this is generally limited to drum surfaces and internals)

    including: primary and secondary steam separation devices, feedwater

    penetrations, instrument and blowdown penetrations and baffle plates and their

    mechanical restraints (bolting and/or welds).

    In addition to these routine activities, plants with a history of HRSG component damage

    may also schedule dye penetrant (PT) inspection of areas susceptible to certain types

    of cracking, radiographic testing (RT) of tube-to-header welds when there is a suspicion

    of weld defects or sub-surface cracks. Thermography of HRSG casings is performed at

    some plants to identify hot spots, but is more commonly applied to older units which

    have accumulated more operating hours. Additional information on inspection planning

    is available in Reference 1.

  • Borescope inspections are relatively uncommon for large HRSG components due to a

    general lack of access to areas of interest; one exception is their use to perform

    inspections of attemperator spray liners. Attemperator sprays have been a significant

    problem for a variety of reasons including: poor engineering designs of spray line layout

    and control by HRSG OEMs, premature failure of some spray valve components in the

    field due to manufacturing/QC causes and a tendency to “overspray” in order to control

    metal temperatures in Reheater (and HP Superheater) outlet piping to below design

    values for units that are subject to heavy cycling.

    Based on performing more than 50 of these inspections in the past few years (about

    80% of all inspections have been for large reheat HRSGs), we have prepared some

    general observations about early operating experiences for relatively new HRSGs.

    These inspections include a wide variety of GT/HRSG combinations as indicated in

    Figure 2. While the HRSG is typically the major component that must be designed to be

    compatible with the specifications of the CT and the STG, there are some significant

    generalizations that have been observed with respect to early damage and operational

    problems.

  • 0

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    4

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    6

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    W50

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    Aalborg Alstom AnsaldoCerrey Deltak DoosanFoster-Wheeler

    IHI NEM Nooter Toshiba Vogt

    4321

    Sum of No Inspected

    No Inspected

    Figure 2. Inspections by CT and HRSG Type

    Figure 3 summarizes the relative frequency of the dominant damage mechanisms and

    related problems that we have encountered in performing these inspections. It does not

    include routine operating issues such as drum level control, etc. Not surprisingly, it is

    mechanisms which are most aggravated by cycling conditions (tube bowing, leaks and

    failures, gas baffle damage, desuperheater spray malfunctions, design issues and

    related controls problems and drain leaks and failures) that are most common.

  • 0% 5% 10% 15% 20% 25% 30% 35% 40% 45%

    Baffles (minor)

    Tube Damage (minor)

    Drains

    Desuperheaters

    Piping

    Tube Damage (severe)

    Casing

    Drums and Internals

    Baffles (severe)

    Corrosion/ Iron Transport

    Cold End

    Flow Conditioning

    Supports (minor)

    Supports (severe)

    Duct Burner IssuesD

    amag

    e M

    echa

    nism

    % of HRSGs Affected

    Figure 3. Frequency of Common HRSG Damage Mechanisms

  • Some of these cycling related damage mechanisms (such as tube leaks and failures)

    have been significant enough to require (or cause) plant shutdown. Others have been

    detected during scheduled HRSG inspections. The approach taken in this paper is

    largely anecdotal; typical experiences will be discussed for each class of mechanisms.

    While much of the focus of good operations and maintenance practice is oriented

    toward controlling corrosion of susceptible materials, primarily the carbon steel

    components that comprise most of the HRSG surface area, one immediate observation

    is that corrosion – at least so far – is not a significant problem at most plants. This is

    less a consequence of excellent water chemistry control than it is simply too early to

    detect small amounts of corrosion shortly after commissioning.

    Flow accelerated corrosion (FAC) is a high-visibility issue which has been the cause of

    numerous fatalities at power plants over the years. FAC has not been detected at new

    reheat units although in general they have not operated long enough to experience

    significant wear, even for the highest risk locations. Experience from previous HRSG

    designs that have operated for longer periods (50,000 – 100,000 hrs) indicates that will

    likely change despite the best efforts of plant staffs to maintain water chemistry within

    targets.

    Those units with some cold end corrosion problems generally have a combination of

    design issues, fuel gas quality issues and often frequent exposure of susceptible

    surfaces to high ambient humidity with long periods of layup.

  • Casing, Liner and Gas Baffle Damage

    The most prevalent mechanism encountered in new units is damage to gas baffles.

    Due to the nature of their geometry and proximity to a variety of potential interferences,

    these structures are often subject to fatigue, distortion from thermal expansion and

    interference and to high vibrations, particularly in the hot sections of the HRSG. Casing

    and liner plate damage are also common with hot spots typically evident on the casing

    surface, around doors and anywhere there is insufficient insulation. Liner plates are

    generally damaged by thermal buckling, over constraint due to bolting/welding design

    and overheating in firing ducts. Some examples of these damage mechanisms follow.

    Figure 4. Casing Hot Spot Below Transition Duct Floor

  • Figure 5. Failed Gas Baffle

    Figure 6. Failed Casing Seal Weld around Reheat Connection to Lower Manifold

  • Figure 7. Failed Transition Duct Casing Liner

    Figure 8. Buckled Liner Plates in Firing Duct

  • Figure 9. “Pinhole” in Fabric Expansion Joint

  • Tube and Header Leaks and Failures

    The most significant damage that occurs in HRSGs is generally leaks and failures of

    pressure parts; specifically, tubes, headers and connecting piping. Tube failures are

    well known as dominant contributors to plant unreliability. While tube repairs are not

    lengthy procedures, they contribute substantially to the cost of cycling duty when they

    occur. Leaks and failures in larger components such as headers, major connecting

    piping and steam piping can require more lengthy outages with correspondingly greater

    costs. The most common tube damage mechanism is probably bowing which is

    attributable to a variety of sources including differential thermal stress, manufacturing

    variations in tube length, etc. From our inspections of new (pre-operational) units, we

    have observed that some slight tube bowing is sometimes present prior to operation.

    However, large displacements are not observed pre-service. Tube failures are less

    common, but have occurred at many large reheat HRSGs. The root causes of these

    failures varies and depends on many factors including: material type, exposure to high

    temperatures (gas temperature) during startup followed by quenching from condensate

    accumulation or excess attemperation spray, waterhammer and stress corrosion

    cracking. Flow accelerated corrosion (FAC) has not been observed in these relatively

    new units to date. Samples of these degradation types encountered in the field follows.

    Condensate formation during startup is a well-known problem and plants experiencing

    repeated tube failures, extreme tube bowing and or related problems with attemperation

    spray equipment have sometimes installed temporary thermocouples to more

    accurately ascertain the temperature variations in reheater (and superheater) tubes.

    Some plants have also installed thermocouples to determine whether steam binding is

    occurring in HP Economizers that are poorly vented. Diagnosis of tube failures is often difficult and generally requires the support of a trained

    metallurgist. General guidance on types of tube failure mechanisms and their

    identification is provided in Reference 2.

  • Figure 10. 70° Kink in Reheater Tube – Cycling Unit

    Figure 11. RH Tubes Thermocouples Identify Condensate During Startup/Shutdown

  • Figure 12. Bowed RH Tubes below Cold Reheat Inlet following Waterhammer Event

    Figure 13. Low Cycle Fatigue Failure of T91 Reheater Tube – Cycling Unit

  • Figure 14. Tensile Overload Failure of T91 Reheater Tube – Cycling Unit

    Figure 15. Fatigue Failure of 304H Stainless Reheater Tube Stub – Cycling Unit

  • Figure 16. Tube Leak in T91 Reheater Tube Stub – Horizontal Section – Cycling Unit

    Figure 17. Welding/Manufacturing Defect in Leaking HP Economizer Tube – Cycling Unit

  • Figure 18. Stress Corrosion Cracking Failure in LP Feedwater Tube – Cycling Unit

    Figure 19. Crack in P22 Reheater Header Weld – Cycling Unit

  • Figure 20. Header Window Weld for Inaccessible Tube-to-Header Repair – Cycling Unit

  • Boiler and Steam Piping Damage

    Problems with boiler and steam piping is often associated with the reheat piping;

    particularly where attemperator sprays have been designed with too short downstream

    straight pipe lengths (less than 10 pipe diameters). Incomplete atomization of

    attemperator sprays impacts downstream piping surfaces as liquid droplets where it can

    cause significant thermal stresses.

    Waterhammer is another phenomenon that has occurred at a number of combined

    cycle plants. It is often attributed to a combination of problems related to spray valve

    control, drainage of condensate or abrupt valve actuation. Waterhammer is generally a

    destructive transient; casualties typically include adjacent piping supports with yielding

    of steam piping a common end result. Examples of typical boiler and steam piping

    damage from these mechanisms follow.

    Figure 21. Leaking 16” Reheater Crossover Link Piping – Cycling Unit

  • Figure 22. Waterhammer Damage to Cold Reheat Piping and Supports – Cycling Unit

    Figure 23. IP Feedwater to IP Drum Leak – Cycling Unit

  • Figure 24. DSH Spray Line Leak – Cycling Unit

  • Drain Leaks and Failures

    Drain leaks and failures are another relatively common problem for newer units as

    indicated in Table 2. Drains are often cocked or otherwise bent during final construction

    when the pre-fabricated tube panel assemblies are connected in the field to the drain

    system. The result is often drain welds that are under considerable stress due to

    misalignment in casing holes and/or misalignment of drain tube stubs with the field

    drainwork. While relatively easy to repair, drain leaks have in some cases led to drum

    level instability requiring emergency plant shutdown. Inspection of accessible drain

    welds during scheduled HRSG Inspections is an effective way to reduce the likelihood

    of a drain failure during operation.

    Figure 25. Bent HP SH Drain

  • Figure 26. Leaking Feedwater Preheater Drain

    Figure 27. Weeping Crack in Drain Weld Below LP Economizer Crossunder Piping

  • Drum and Internals Damage

    Damage to drum surfaces and internals includes problems with baffle weld designs,

    accumulation of tubercle deposits over pits in HP and LP drums and some small defects

    in drum shell surfaces. Because most of these new large units have been operating for

    only a few years there have been no incidents of severe corrosion of steam separation

    devices, development of fatigue cracks or other serious damage. However, many

    merchant plants spend extended periods in relatively long layup. Those employing dry

    layup with a nitrogen cap typically find relatively minor surface oxide. Some owners are

    using wet layup to accommodate the possibility for a more rapid startup; these units

    sometimes have greater incidence of tubercle formation with small pits underneath and

    adhered deposits on the drum shell. Sludge piles are often evident in LP Drums where

    iron transport is a problem due to inadequate control of oxygen levels. Cycling

    operation is not conducive to maintaining stable water chemistry and many operators

    are challenged to maintain their water chemistry within targets. Examples of these

    conditions follow.

    Figure 28. Tubercles Covering Shallow Pits in HP Drum

  • Figure 29. Adhered Deposits at Waterline – IP Drum

    Figure 30. Shallow Pit Below Tubercle in LP Drum

  • Figure 31. Sludge Pile in LP Drum

    Figure 32. Cracked HP Drum Baffle Plate Weld

  • Cold End Corrosion

    Cold end corrosion is enhanced in many merchant plants because they are operating

    for more time at part load than anticipated by design (and therefore component surface

    temperatures may be below the acid dewpoint temperature where acids will condense

    on tube surfaces and corrosion damage will occur). This problem is aggravated by

    greater than anticipated sulfur content in fuel gas in some locations. Older units have

    employed CO2 blasting to remove some of the deposits, but the effectiveness is limited

    if the affected harp (typically the LP Economizer or Feedwater Heater) has many tube

    rows.

    Another damage mechanism that has caused tube failures in cold end components (see

    preceding discussion above) is stress corrosion cracking. This damage mechanism

    affects susceptible materials and can result in tube leaks or failures in a very short time

    (few years of operation). This mechanism may be accompanied by the accumulation of

    ID deposits which tends to protect and concentrate aggressive chemical species.

    Accumulation of ID deposits implies problems with feedwater water treatment and

    control.

    Occasionally, bowed tubes are observed in the cold end of large units; sometimes these

    are near the feedwater inlets where the inlet water temperature may be significantly

    colder than adjacent tubes depending on the flow pattern in the harp design. This can

    lead to large thermal stresses between tubes.

  • Figure 33. Ammonium Bisulfite Accumulation on Feedwater Heater Final Row

    Figure 34. Sticky Deposits (pH = 3) on LP Economizer Tubes

  • Flow Distribution Device Damage and Failures

    Not all HRSGs have flow distribution devices. Their specification depends on a variety

    of factors related to the CT, geometry of the transition duct, general layout of the HRSG

    (# modules wide, height of unit), etc. When flow distribution devices are installed, there

    can be problems especially when they are upstream of the lead tube bank (which is

    where they need to be to re-distribute flow to higher tube elevations). In some cases a

    second flow distribution grid is installed upstream of duct burners to further modify the

    exhaust gas flow, although this is not common.

    The most common design is the perforated plate design although other approaches

    have included large turning vanes and smaller sets of turning vanes. The most

    common problem is fatigue damage that is attributable to the high gas velocity and often

    inadequate structural support that is provided to hold the perforated plate in position.

    Often, the support structure behind the plate experiences extensive fatigue failures

    which weakens the plate and in turn fatigue begins to fail ligaments between the holes

    in the perforated plate. Examples of these problems follow.

    Figure 35. Fatigue Cracks in Ligaments and Stiffening Plates in Flow Distribution Grid

  • Figure 36. Failed Flow Distribution Grid Vanes

    Figure 37. Failed Component Embedded in Lead Tube Bank

  • Duct Burner Issues

    Duct burners are used to increase steam production, either to compensate for reduced

    output due to ambient conditions or for additional (peaking) output. Duct burners can

    impact on the reliability of downstream tubes if flame impingement occurs. Typically,

    this can happen if the firing duct is not sufficiently long to accommodate the length of

    the burner flame. In this case the end of the flame is actually in the downstream tube

    panel. Local overheating of tubes has been attributed in some cases to excessive duct

    firing. Other problems with duct burners have involved the burner elements

    themselves either being improperly positioned or falling out of their supports during

    operation so they were no longer supported at both walls. Some examples of these

    problems follow.

    Figure 38. Duct Burner Flame Impingement on Downstream Tubes

  • Figure 39. Unfired Duct Burner Runner – 90° Out of Position

    References

    1. HRSG Inspection Planning Guide, Tetra Engineering Group, 2003.

    2. HRSG Tube Failure Diagnostic Guide, Second Ed., Tetra Engineering Group,

    2004.